ENGINEERING ANALYSIS

Source Name: Gateway Cogeneration 1 LLC Permit No.: 52375-002

Source Location: Chudoba Parkway, Prince George, Virginia Engineer: AMS

Date: August 23, 2012

I. Introduction and Background

A. Company Background

The facility, as proposed, will be a new combined cycle electrical power generating facility. The facility will be located on Chudoba Parkway in Prince George County, which is in attainment for all pollutants. It will be a major source of greenhouse gas (GHG), triggering Prevention of Significant Deterioration (PSD) permitting for GHG, PM 1 0, and PM 2 5 emissions.

The company is located on a site which is suitable from an air pollution standpoint. Additionally, the county of Prince George has certified that the location and operation of the facility are consistent with all applicable ordinances adopted pursuant to Chapter 22 (§15.2-2200 et seq.) of Title 15.2 of the Code of Virginia (see attached Local Governing Body Certification Form).

B. Proposed Project Summary

The proposed project will be a nominal 160 MW combined cycle electrical power generating facility utilizing two combustion turbines each with a heat recovery steam generator (HRSG) and no duct burning. The proposed fuels are natural gas and ultra low sulfur diesel (ULSD) as back up (with a maximum of 500 hours of operation on ULSD). Emissions from the turbines will be controlled by the use of low carbon fuels and high efficiency design (for GHG), clean fuels and good combustion practices (for PM 1 0 and P M 2 5 emissions), SCR and water injection (for NOx), and oxidation catalyst (for CO and VOC). A cooling tower and fuel tanks are also proposed, as well as an emergency diesel fire pump. Electrical circuit breakers potentially emit GHG pollutants (expressed as carbon dioxide equivalents, or C0 2-e) so they will be covered in the permit as well.

C. Process and Equipment Description

Equipment to be Constructed Ref. No.

Equipment Description Rated Capacity Federal Requirements

CT01 Rolls Royce Trent 60 WLE Combustion Turbine with associated HRSG

64 MW (CT only) 593 MMBtu/hr on natural gas 583 MMBtu/hr on ultra low sulfur diesel

NSPS Subpart KKKK

CT02 Rolls Royce Trent 60 WLE Combustion Turbine with associated HRSG

64 MW (CT only) 593 MMBtu/hr on natural gas 583 MMBtu/hr on ultra low sulfur diesel

NSPS Subpart KKKK

FP01 Emergency Diesel Fire Pump 1.86 MMBtu/hr (250 BHP) NSPS Subpart IIII (non-delegated) MACT Subpart ZZZZ (non-delegated)

TR01 Mechanical Draft Cooling tower 55,000 gallons/min. EB01 Four electrical circuit breakers 60 lb SF6per breaker

Equipment Exempt from Permitting Ref. No. Equipment Description Rated Capacity Exemption Citation Exemption Date

TK01 Vertical fixed roof storage tank for ultra low sulfur diesel

115,000 gallons 9 VAC 5-80-1320 B 4 August 27, 2012

Engineering Analysis August 23, 2012 Page 2

D. Project Schedule

Date permit application received in region: January 11, 2012 Date application was deemed complete: January 11, 2012 Proposed construction commencement date: September 1, 2012 Proposed start-up date: December 1, 2013

II. Emissions Calculations (see attached spreadsheets)

Emissions from startup and shutdown were included in the annual permit emissions limits for the combustion turbines, but separate limits will not be included. Short-term C0 2-e emissions were not included in the permit because there is no regulatory basis to do so, however, annual limits on a ton/yr and Ib/MWh basis will be included.

The turbines will be limited to 4.2 x 106 gallons of ULSD fuel per year. This is equivalent to 500 hours of operation using the following equation:

MMBtu MMBtu hours gals „ gals 583—; per turbine x 2 turbines + 0.138 — x 500 = 4,224,637.7- = 4.2 x 10 6-

hr gal yr yr yr III. Regulatory Review

The proposed project is a major new source with projected permitted emissions of C0 2-e over 100,000 tons and PM 1 0 emissions over 15 TPY. The source is located in an area that is in attainment for all pollutants.

Federal Regulatory Review:

Greenhouse Gas Tailoring Rule:

After July 1, 2011, new sources that have the potential to emit 100,000 tons or more of C0 2-e and modified sources with a net emission increase of C0 2-e over 75,000 tons year will be required to obtain a PSD permit. The total C02-e is based on taking the mass emissions of each GHG and multiplying by its Global Warming Potential (GWP). These GWP factors are as follows: C0 2 : 1; CH4: 21; N20: 310; SF6: 23,900; HFCs: 140 to over 11,700; and PFCs: 5,210 to 9,200. The first three GHG pollutants are primarily from fuel burning and the latter pollutants are from semi-conductor and other production processes. This facility has electrical circuit breakers which contain SF6.

Since any permit for the project would be issued after July 1, 2011 and permitted C0 2-e emissions will be greater than 100,000 tons, the source would be subject to PSD permitting.

PSD Permitting: The source is subject to PSD permitting for C0 2-e emissions which are over 100,000 tons/yr (see Table 1 below). Because one pollutant is subject to PSD, the other pollutants at the source need to be evaluated for PSD at their significance level. PM 1 0 and PM 2 5 both exceed the PSD significance level for each pollutant so the facility will be subject to PSD for GHG (C02-e), PM 1 0, and PM 2 5 . The source is required to apply BACT for these pollutants. BACT for these pollutants is discussed in Section III.C.

Table 1- PSD Permitting applicability Pollutant Potential to

Emit (TPY) PSD Major Threshold (TPY)

Over Major Threshold?

PSD Significance Rate (TPY)

PSD Required?

CO 49.9 100 N 100 N NOx 39.2 100 N 40 N PM 1 0 48.9 100 N 15 Y P M 2 5 48.9 100 N 10 Y

Engineering Analysis August 23, 2012 Page 3

Pollutant Potential to PSD Major Over Major PSD PSD Emit (TPY) Threshold Threshold? Significance Required?

(TPY) Rate (TPY)

so2 7.7 100 N 40 N

VOC 23.5 100 N 40 N GHG (C0 2 + CH 4 + N 20 + SF 6 591,265.1 100 Y C0 2-e 591,978 100,000 Y Y

NSPS Requirements: The combustion turbines are subject to NSPS subpart KKKK (Standards of Performance for Stationary Combustion Turbines) which requires the source to meet NOx and S0 2

standards. The source must meet a NOx limit of 25 ppm when burning natural gas, and a 74 ppm limit when firing ULSD oil. The source proposes the use of water injection (WLE) and SCR to control NOx emissions. NOx emissions from the proposed combustion turbines are expected to be around 2.0 ppmvd when burning natural gas, and 5.0 ppmvd when burning ULSD - which are below the NSPS standards and are considered Best Available Control Technology (BACT). The source will put NOx CEMS on the turbine stacks to show compliance with the BACT limits.

The source proposes using low-sulfur fuels (ULSD at 0.0015% sulfur and natural gas) to control S0 2 . To be in compliance with NSPS KKKK, they must not exceed 0.90 lb S02/MWh emissions, or 0.06 lb S02/MMBtu from fuel burning. The source has proposed a voluntary emission limit of 0.0016 lb S02/MMBtu or 0.3 ppmvd @ 15% 0 2 (PSD and State BACT do not apply). BACT is discussed in more detail in Section III.C.

A new NSPS (Subpart TTTT) could possibly be in place before this source constructs the turbines so the turbines could be subject to that subpart. The proposed standard is a C0 2 emission limit of 1,000 Ib/MWh (gross annual average considering all operation), although a range has been examined that covers 950-1100 Ib/MWh. Expected emissions of C0 2 from the facility are around 1050 Ib/MWh on the same basis, though the specific value is dependent on actual operating modes. When the source conducts Part 75 monitoring for Acid Rain, it will fulfill the proposed monitoring requirements for NSPS Subpart TTTT.

Finally, the diesel fire pump is subject to NSPS Subpart IIII. It is subject to a NOx + non-methane hydrocarbon (NMHC) limit of 3.0 g/hp-hr, a PM limit of 0.15 g/hp-hr, a CO limit of 2.6 g/hp-hr, and a requirement to use ULSD with no more than 15 ppm sulfur content. Although the source must be in compliance with these limits, DEQ has not elected to receive delegation for enforcement of this regulation, so no requirements specific to this regulation will be included in this permit. BACT limits will be used to ensure the NSPS standards are met.

MACT Requirements: The diesel fire pump (emergency, stationary, RICE less than 500 hp located at an area source) is also subject to MACT Subpart ZZZZ (40 CFR 63.6590.c1). Compliance with this MACT is met by complying with NSPS Subpart IIII requirements. DEQ has not elected to receive delegation to enforce this EPA regulation so requirements for this specific regulation will not be included in the permit.

As an area HAP source, the facility will not be subject to MACT Subpart YYYY for turbines or MACT Subpart Q for cooling towers.

Other: The source will also be subject to the Acid Rain permit regulations but will seek an Acid Rain permit at a later date. The source will be subject to Title V permitting and must submit a Title V application within a year of commencing operation.

State New Source Review:

The combustion turbines are subject to Virginia Article 6 permitting for new and modified sources as their uncontrolled emissions exceed the values in 9 VAC 5-80-1320 C for PM 1 0, CO, NOx and VOC. The other emissions units at the facility are exempt from Article 6 permitting (see Table 2 below.

Engineering Analysis August 23, 2012 Page 4

Table 2- Article 6 Emissions Applicability PMio CO S0 2 NOx VOC

CT01 65.7 114.9 4.09 812.03 56.56 CT02 65.7 114.9 4.09 812.03 56.56 Tanks - - - - 0.02 Fire Pump 0.01 0.14 0.01 0.17 0.06 Cooling Tower 0.45 - - - -Electrical Circuit Breaker - - - - -Totals 131.86 229.94 8.19 1624.23 113.20 Article 6 threshold 25 100 15 40 40 Subject to Article 6? Yes Yes No Yes Yes

Note: Uncontrolled emissions from the combustion turbines were back-calculated based on the following assumptions: Control efficiency for NOx from SCR + WLE = 94% Control efficiency for CO from Ox Cat = 80% Control efficiency for VOC from Ox Cat = 80%

Existing Source Rules:

The exempt fuel oil tank is not subject to Rule 4-37 (Emission Standards for Petroleum Liquid Storage and Transfer Operations) because it holds only diesel oil with a vapor pressure less than 1.5 psia. The fire pump is subject to Rule 4-4 (Emission Standards for General Process Operations) as a combustion installation but must meet the standards of NSPS IIII, which are more stringent.

A. Criteria Pollutants

Criteria pollutant modeling was conducted to ensure that the facility will not violate the NAAQS.

PSD increment Modeled impacts are below the Significant Impact Level (SIL) for PM 1 0 for both Class I and Class II modeling. For PM 2 5 , class I impacts are below the SIL, while Class II impacts exceed the SIL. As such, full modeling was performed for Class II for PM2 5. The results of that modeling show that all impacts are below the PM2 5 NAAQS and Class II PM2 5 increment.

B. Toxic Pollutants

MACTs have been promulgated for Combustion Turbines that are major sources of Hazardous Air Pollutants (HAP) (Subpart YYYY National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines) and for cooling towers at major sources of HAP (Subpart Q National Emission Standards for Hazardous Air Pollutants For Industrial Process Cooling Towers). HAP emissions from this facility will be below major levels, so there will be no MACT requirements for the Combustion Turbines or Cooling Towers and, therefore, the State Toxics Rule will apply. The source will need to demonstrate that they are minor for HAPs. The only HAP that exceeds the exemption rate in 9 VAC 5-60-300 is formaldehyde. It will appear in a State Only section of the permit. Modeling has shown that formaldehyde emissions will not exceed the Standard Ambient Air Concentration (SAAC) with impacts less than 1% of the SAAC for both short-term (hourly) and long-term (annual) intervals.

The emergency diesel fire pump is subject to MACT Subpart ZZZZ as an area source as per the application submitted by GGE. The requirements for this unit will be to comply with NSPS subpart IIII requirements, which will be enforced by EPA, not DEQ.

The State Toxics Rule will not apply to either the turbines or the emergency fire pump because the units are subject to a promulgated MACT standard.

Engineering Analysis August 23, 2012 Page 5

C. Control Technology

PSD BACT: Sources that are subject to PSD permitting, must apply BACT to those pollutants that triggered PSD permitting (see Table 1 in Section III). The determination of BACT usually involves a top-down method:

Step 1 - Identify all possible control technologies; Step 2 - Eliminate technically infeasible options; Step 3 - Rank the technically feasible control technologies based upon emission reduction potential; Step 4 - Evaluate ranked controls based on energy, environmental, and/or economic considerations; and Step 5 - Select BACT.

Greenhouse qasses: In this case, C0 2-e emissions from the proposed facility trigger PSD permitting (on both a mass basis and C02-e basis, see Table 1 above) so BACT must be determined for C0 2-e. C0 2-e is a relatively new regulated pollutant so there are few determinations in the RACT/BACT/LAER Clearinghouse to compare, especially for smaller natural gas combined cycle turbines.

Combustion Turbines

1. Possible Control Technologies:

• Carbon capture and sequestration/storage: One such technology that is being discussed to control C0 2 is Carbon Capture and Sequestration/Storage (CCS). CCS consists of concentrating/capturing C 0 2 from exhaust and transporting it to a location where it can be stored for a long time, deep in the ground. It is being demonstrated on pilot-scale power plant projects and on other types of facilities around the world.

• Efficient power generation: Another strategy being used to minimize C0 2 emissions is to maximize the energy efficiency and performance of the turbines. This has been the most accepted BACT for natural gas, combined-cycle plants. By using more efficient turbines (a Trent 60 can reach 42% efficiency from the CT alone) and including the steam system to capture heat from the exhaust, less fuel can be used and C0 2 emissions can be minimized.

• Using low carbon fuel, like natural gas instead of coal, can reduce GHG.

2. Technically infeasible options:

The GGE application concluded that CCS was technically infeasible for a plant such as theirs, but discussed this control option in further steps in the BACT determination process and revisited this argument in a follow-up document (July 5, 2012). Although the CCS technology is available and technically feasible for some applications (such as natural gas processing industries and petroleum refining), and in certain areas of the country, it is not a proven control option for a small, natural gas, combined cycle combustion turbine whose exhaust is characterized by high flow and low C0 2 concentration. There are no instances that could be found of CCS being used on such a facility. The proposed location does not appear to be geologically ideal for CCS but could offer some marginal options. The technology can cause a significant energy penalty (estimated to be up to 15%) which could cause the units to have to burn more fuel and create more air pollution than would otherwise be emitted, and/or reduced power output. CCS works best on larger units, especially coal burning units, which have the potential to emit C0 2 in larger concentrations than this plant.

Engineering Analysis August 23, 2012 Page 6

Efficient power generation and the use of low carbon fuel are feasible for this GGE project.

3. Rank technologies

Since BACT is based on an emission limitation which reflects the maximum degree of reduction for a particular pollutant, then the best means of comparison is of emission limits rather than % control efficiency. Since energy efficiency plays a role in emissions, one must compare efficiency limits based on output (Btu/kWh) rather than mass limits based on heat input (Ib/MMBtu). This is because, as a unit gets older and less efficient, it may still meet a Ib/MMBtu limit while, at the same time, using more fuel to achieve its heat input need, therefore increasing emissions. Only a handful of CCT have been permitted for GHG so a quick comparison can be made. As can be seen in Table 3 below, this project is much smaller than most of the other, recently permitted or proposed NGCC projects. Keeping in mind that thermal efficiency increases with larger turbines, and the net heat rate (Btu/kWh) decreases, the difference in BACT levels between the proposed 160 MW plant and the permitted or proposed 500+MW plants can be explained. The Gateway plant also has oil backup which could impact efficiency. When comparing a heat rate limit, it is important to know whether it is based on a HHV or LHV and whether it is for a gross power output or a net power output. This is not always evident. Also, some GHG BACT proposals include a "degradation factor" which takes into consideration the heat rate of a unit as it gets older and less efficient. Other GHG BACT proposals may not (see discussion of the proposed BACT in GGE's July 5, 2012 submittal).

Table 3 - Comparison of GHG BACT determinations Facility Type GHG BACT Gateway Cogeneration 1 160 MW NGCC w/oil backup 8983 Btu/kWh (gross HHV,

including degradation) Thermal Efficiency

Cheyenne Light, Fuel, & Power 220 MW NGCC 7062 Btu/KWh (gross HHV) Thermal Efficiency Palmdale Hybrid Power 570 MW NGCC and 50 MW

solar collectors 7319Btu/kWh Thermal Efficiency

Lower Colorado River Authority 590 MW NGCC 7720 Btu/kWh Thermal Efficiency Russell City Energy Ctr 600 MW NGCC 7730 Btu/kWh (including

degredation) Thermal Efficiency

PacifiCorp 629 MW NGCC 950 Ib/MWh Thermal Efficiency CPV (St. Charles, MD) 725 MW NGCC 7605 Btu/kW Thermal Efficiency Cricket Valley Energy Ctr 1,000 MW NGCC 7605 Btu/kWh (net LHV) Thermal Efficiency

No information could be found on GHG BACT limits for a natural gas combined cycle power plant using CCS for comparison with a thermal efficiency approach but estimates have shown it to be about 90% effective in reducing GHG emissions. One study1 predicted that a natural gas-fired power plant that had a C0 2 emission rate of 803 Ib/MWh could reduce emissions to 94 Ib/MWh by adding CCS, but at a cost of $1336/kW.

4. Most effective Controls

Of the technologies mentioned in Step 1 above, construction of a carbon capture control, transport and storage system for C0 2 gas in the Prince George County region would be cost-prohibitive. The capital cost for the project is estimated to be $136 million. A recent study suggested that adding CCS technology could increase plant construction costs up to $200 million2. These factors, and the cost from a 15% energy penalty which increases fuel usage, would make CCS economically infeasible at this time (see discussion from GGE's July 5, 2012 submittal).

1 Rubin, Edward S and Haibo Zhai. The Cost of Carbon Capture and Storage for Natural Gas Combined Cycle Power Plants. Environ. Sci. Technol. 46:3076-3084(2012) 2 Fishbeck, Paul S, David Gerard, and Sean T McCoy. Sensitivity analysis of the build decision for carbon capture and sequestration projects. Greenhouse Gas Sci. Technol. 2:36-45 (2012)

Engineering Analysis August 23, 2012 Page 7

The remaining technologies, namely efficient power generation and the use of low carbon fuels, are proposed for this facility and are accepted as BACT. The plant will be required to use no more than 500 hours/yr of fuel other than natural gas (ULSD) and to operate at a higher heating value heat rate 8,983 Btu/KWh.

Fire Pump Add-on C0 2 controls are not feasible for emergency generators so BACT for the fire pump will be fuel-efficient design and a limit of 200 operating hours/yr.

Electrical Breakers The electrical circuit breakers contain SF 6 which is a GHG. There is a small potential for these sealed units to release SF6 from leaks. Although an alternative to the SF 6 would be to use oil or air-blast circuit breakers, which would not have the potential to release SF6, this technology is being replaced by the sealed SF 6 circuit breakers due to the superior insulating and arc-quenching capabilities of the SF6 type units. The oil and air-blast units are also larger than the SF 6 units, generate more noise, and the dielectric oil is flammable and also has adverse environmental impact if released. Studies have shown that the leakage rate for SF 6 from these circuit breakers is between 0.2 and 2.5 percent over the lifetime of the unit.3 Therefore, BACT for the circuit breakers will be to minimize SF6 leakage by using an enclosed-pressure circuit breaker with a 1.0 percent annual leakage rate (equivalent to 0.0012 Ib/yr) and a leak detection system.

Particulate Matter (PMin and PM?s, including condensable) - Because the turbines are subject to PSD for GHG, other pollutants need to be compared to the significance rates in 9 VAC 5-80-1615. If the annual emission rate of any pollutant is higher than the significance rate, that pollutant is subject to PSD. Table 1 above shows that Particulate Matter (PM 1 0 and PM 2 5 ) also triggers PSD review, and therefore determination of BACT.

Combustion Turbines Add-on PM controls (such as scrubbers or baghouses) are not recommended for combustion turbines burning natural gas because the PM particles are quite small (<1 micron) and the air volume is quite large, thus diluting PM. Therefore, turbine design and operation limitations must be reviewed. The use of low-ash fuel (natural gas and ULSD) and good combustion practices are widely accepted as PSD BACT for PM 1 0 and PM2 5 from combustion turbines and so are accepted as BACT for these units to achieve emission limits of 5.0 Ib/hr when burning natural gas and 15.0 Ib/hr when burning ULSD.

Fire Pump Possible PM controls for an emergency generator consist of the following: catalysts, including diesel particulate filters, clean fuels and good combustion practices. Of these, catalysts are not used for units that are only run on an as-needed basis, making them not technically feasible for this unit. Therefore, PSD BACT for PM from the fire pump shall be the use of clean fuels (i.e., natural gas and ULSD) and good combustion practices to achieve an emission limit for PM 1 0

and PM 2 5 of 0.15 g/hp-hr (0.083 Ib/hr).

Cooling Tower

Cooling towers produce drift, which is composed of fine water droplets that may contain dissolved solids and thus contribute to PM emissions. The only feasible PM controls for cooling towers is to use water with low total dissolved solids content and drift eliminators. The facility will use clean cooling water and has proposed the use of drift eliminators. BACT for PM from

3 SFe Leak Rates from High Voltage Circuit Breakers - U.S. EPA Investigates Potential Greenhouse Gas Emissions Source, J. Blackman (U.S. EPA, Program Manager, SF6 Emission Reduction Partnership for Electric Power Systems), M. Averyt (ICF Consulting), and Z. Taylor (ICF Consulting), June 2006.

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the cooling towers will be to keep dissolved solids below 1200 mg/l and to achieve a drift rate of 0.001 percent of the circulating water flow (equivalent to 0.5 TPY of PM 1 0 and 0.3 TPY of PM 2 5 .

State BACT: New units, whose uncontrolled emissions exceed the exemption levels in 9 VAC 5-80-1320 C, are required to apply State BACT to emissions (See Table 2 in Section III). State BACT does not require a formal top-down analysis of control options, but must be no less stringent than any NSPS or MACT standard. State BACT is determined on a case-by-case basis, taking into consideration energy, environmental and economic impacts and other costs.

Since emissions from the combustion turbines exceed the exemption level for PM 1 0, NOx, CO, and VOC, State BACT applies to those pollutants (no other units trigger BACT). However, since PMio is subject to federal BACT, state BACT for PM 1 0 is redundant.

Combustion Turbines

PM - State BACT for PM and PM 1 0 from the combustion turbines will be the same as for the PSD BACT, namely the use of low-ash fuel (natural gas and ULSD) and good combustion practices.

NOx - The facility proposes a NOx limit of 2 ppm on NG and 5 ppm on ULSD, using wet, low emission (WLE) turbines and SCR to control NOx. This is comparable to other facilities that have been recently permitted across the country (see tables in permit application). In most cases, lower emission rates reflect LAER rather than BACT so they are not comparable with this facility.

CO - CO emissions from the turbines are proposed to be 4 ppm (on either NG or ULSD) using good combustion practices and oxidation catalyst. This is a lower BACT than many similar combustion turbines permitted across the country (see tables in permit application). Those combustion turbines that have a lower BACT for CO (around 2-3 ppm) have a larger NOx emission rate (2.5 ppm). This facility chooses to minimize NOx and CO at the same time, so the proposed State BACT is acceptable.

VOC - The facility proposes a VOC limit of 2 ppm (on either NG or ULSD) using good combustion practices and oxidation catalyst. This is comparable to most units which were recently permitted (see tables in permit application). Those projects that had a lower VOC limit had a much higher NO x limit. As with CO, by minimizing both NOx and VOC at the same time, VOC emissions might be a bit higher than similar facilities with a higher NOx limit.

SU/SD - During startup and shutdown, post-combustion controls are not as effective as during normal operation. The source proposes secondary state BACT limits for NOx, CO and VOC during these periods. The source will use CEMS for NOx and CO and, since VOC and CO are produced from similar conditions and both are controlled with oxidation catalyst, then the CO CEMS will also act as a surrogate parameter for VOC emissions, in that, complying with the CO limit will demonstrate compliance with the VOC limit.

Table 4 below summarizes BACT for the facility:

Pollutant Primary BACT Control Secondary BACT (State)

Compliance

NOx (State)

Turbines 2.0 ppmvd - gas (3-hour avg.) 5.0 ppmvd - ULSD (3-houravg.)

Water injection and SCR 19.5 tons/yr NOx CEMS

CO (State) Turbines 4.0 ppmvd (3-hour avg.)

Oxidation catalyst 24.9 tons/yr CO CEMS

Engineering Analysis August 23, 2012 Page 9

Pollutant Primary BACT Control Secondary BACT (State)

Compliance

PM 1 0

(Federal and State) and

PM 2 5

(Federal)

Turbines 5.0 lbs/hr gas (3-hour avg.) 15.0 lbs/hr ULSD (3-hour avg.)

Proper operation and maintenance on the turbines

stack test

PM 1 0

(Federal and State) and

PM 2 5

(Federal)

Fire Pump 0.15 g/hp-hr

Clean fuel and good combustion practices

stack test

PM 1 0

(Federal and State) and

PM 2 5

(Federal) Cooling Tower Drift rate of 0.001% of circulating water flow

Low total dissolved solids (TDS) and drift eliminators

Weekly water quality testing for TDS

VOC (State) Turbines 2.0 ppmvd (3-hour avg.)

Oxidation catalyst 11.7 tons/yr stack test and CO CEMS compliance

C0 2-e (Federal)

Turbines 8,983 Btu/kWh (HHV gross) and 1050 Ib/MWh

Energy efficient combustion practices and low GHG fuels

ASME Performance Test Code on Overall Plant Performance (PTC 46) and C0 2

CEMS (Part 75) C0 2-e (Federal) Fire Pump

74.21 kg/MMBtu Fuel-efficient design 74.21 kg/MMBtu

HHV and fuel usage monitoring

C0 2-e (Federal)

Electrical Circuit breakers

Enclosed-pressure type breaker and leak detection

Audible alarm with decreased pressure.

The proposed control strategies are considered to be the Best Available Control Technology (BACT) for this source type and are more stringent than NSPS standards.

IV. Initial Compliance Determination

A. Testing - stack testing is required for PM 1 0 from the turbines to show compliance with the BACT limit. An initial compliance test using ASME Performance Test Code on Overall Plant Performance (ASME PTC 46-1996) is to be conducted on the turbine power blocks to show compliance with the heat rate limit of 8,983 Btu/kWh (HHV gross). S0 2 will be monitored by fuel testing and certification to show compliance with the voluntary limit of 0.3 ppmvd @ 15% 0 2 for the turbines.

B. VEEs - an initial VEE will be required for the combustion turbines while burning ULSD oil, within 60 days of burning ULSD oil for the first time.

V. Continuing Compliance Determination

A. CEMS - will be required for NOx (NSPS) and is also proposed for CO (and CO as a surrogate for VOC). Requirements for CEMS performance evaluations, quality assurance, and excess emissions reports will be included in the permit.

B. Recordkeeping - The following records will be kept by the permittee for the most recent five years:

a. Annual hours of operation of the emergency fire pump (FP01), calculated monthly as the sum of each consecutive 12-month period. Compliance for the consecutive 12-month period shall be demonstrated monthly by adding the total for the most recently completed calendar month to the individual monthly totals for the preceding 11 months.

b. Annual throughput of natural gas and ULSD to the combustion turbines (CT01, CT02), calculated monthly as the sum of each consecutive 12-month period. Compliance for the consecutive 12-month period shall be demonstrated monthly by adding the total for the most

Engineering Analysis August 23, 2012 Page 10

recently completed calendar month to the individual monthly totals for the preceding 11 months.

c. Time, date and duration of each malfunction period for each combustion turbine (CT01, CT02)

d. All fuel supplier certifications.

e. Continuous monitoring system emissions data, calibrations and calibration checks, percent operating time, and excess emissions.

f. Operation and control device monitoring records for each SCR system and oxidation catalyst as required in Conditions 8 and 9.

g. Weekly log of dissolved solids content of cooling water.

h. Scheduled and unscheduled maintenance, and operator training.

i. Results of all stack tests, visible emission evaluations, and performance evaluations.

C. Further Testing - fuel sulfur monitoring and CEMS for NOx and CO will be required in lieu of additional testing.

VI. Public Participation

The applicant held a public information session on March 13, 2012 at the JEJ Moore Middle School in Prince George County to provide the community with information about the project. As with the earlier rezoning meeting only comments in favor of the project were received at the public information session.

Pursuant to 9 VAC 5-80-1775 (Article 8) of the Regulations, the proposed project is subject to a public comment period of at least 30 days, followed by a public hearing.

An information meeting and public hearing was held on August 8, 2012, followed by 15 more days of public comment.

The following documents are attached:

A. Public hearing notice B. Public hearing opening statement C. Public briefing D. Virginia Register notice E. Documents concerning public comment period

VII. Other Considerations

A. File Consistency Review - This is the first permit action for this source

B. PRO Policy Consistency Review - A review of similar combustion turbine permits proposed or issued in the USA was conducted. The most recent boilerplate was used for this permit.

C. Confidentiality - The source has not claimed confidentiality of any data.

D. Permit History - This is the first permit issued for this source

Engineering Analysis August 23, 2012 Page 11

VI11. Recommendations

Based on the information submitted, it is recommended that this permit be issued.

Attachments: Permit application Local Governing Body Certification Form Calculation sheets

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Gateway Smart Water Project Prince George County 52375-02 AMS

startup 0.167 hr/event 10 min/event

shutdown 0.272 hr/event 16.3 min/event

Annual

Natural Gas ULSD Emissions from

Pollutant SU SD SU SD SU/SD

lb/event lb/event

NOx 5.17 11.21 10.34 28.37

CO 7.75 11.14 8.09 12.74 3.0 tpy

VOC 0.65 1.01 1.19 1.16 1.0 tpy

PM10/2.5 0.64 1.36 1.79 4.070

S02 0.02 0.03 0.02 0.03

Gateway Smart Water Project

Prince George County 52375-02 AMS

Fire Water Pump

250 hp 200 hrs/yr operation

453.59 g/lb 138 MMBtu/kgal

7000 Btu/hp-hr 1.754 MMBtu/hr LHV

138 MMBtu/kgal 1.8649 MMBtu/hr HHV

Emissions

Pollutant EF unit Ib/hr tons/yr

PM10 0.150 g/hp-hr 0.083 0.0083

PM2.5 0.150 g/hp-hr 0.003 0.0003

CO 2.6 g/hp-hr 1.433 0.143

NOx 3 g/hp-hr 1.653 0.165

S02 15 ppmw 0.0028 0.00028

VOC 0.36 Ib/MMBtu 0.671 0.0671

C02 163.055 Ib/MMBtu 304.081 30.408

CH4 0.007 Ib/MMBtu 0.012 0.001

N20 0.001 Ib/MMBtu 0.002 0.000

C02e 163.604 Ib/MMBtu 305.105 30.510

PM10, CO, S02 and NOx EF from NSPS Subpart IIII, Table 4

VOC EF from AP-42 Table 3.3-1 (Oct 96)

GHG EF from 40 CFR Part 98, Table C-l

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Gateway Smart Water Project

Prince George County

52375-02

AMS

Combustion Turbines 592.6 MMBtu/hr total (natural gas)

582.2 MMBtu/hr total (ULSD)

All emission factors are from AP-42 Table

NATURAL GAS Uncontrolled Control Controlled

Pollutant EF Emissions efficiency Emissions

(Lb/MMBtu) Ib/hr tpy Ib/hr tpy

1,3-Butadiene 4.30E-07 2.55E-04 1.12E-03 85% 3.82E-05 1.67E-04

Acetaldehyde 4.00E-05 2.37E-02 1.04E-01 85% 3.56E-03 1.56E-02

Acrolein 6.40E-06 3.79E-03 1.66E-02 85% 5.69E-04 2.49E-03

Benzene 1.20E-05 7.11E-03 3.11E-02 85% 1.07E-03 4.67E-03

Ethyl Benzene 3.20E-05 1.90E-02 8.31E-02 85% 2.84E-03 1.25E-02

Formaldehyde 7.10E-04 4.21E-01 1.84E+00 85% 6.31E-02 2.76E-01

Naphthalene 1.30E-06 7.70E-04 3.37E-03 85% 1.16E-04 5.06E-04

PAH 2.20E-06 1.30E-03 5.71E-03 85% 1.96E-04 8.57E-04

Propylene Oxide 2.90E-05 1.72E-02 7.53E-02 85% 2.58E-03 1.13E-02

Toluene 1.30E-04 7.70E-02 3.37E-01 85% 1.16E-02 5.06E-02

Xylenes 6.40E-05 3.79E-02 1.66E-01 85% 5.69E-03 2.49E-02

ULSD Uncontrolled Control Controlled

Pollutant EF Emissions efficiency Emissions

(Lb/MMBtu) Ib/hr tpy Ib/hr tpy

1,3-Butadiene 1.60E-05 9.32E-03 2.33E-03 85% 1.40E-03 3.49E-04

Benzene 5.50E-05 3.20E-02 8.01E-03 85% 4.80E-03 1.20E-03

Formaldehyde 2.80E-04 1.63E-01 4.08E-02 85% 2.45E-02 6.11E-03

Naphthalene 3.50E-05 2.04E-02 5.09E-03 85% 3.06E-03 7.64E-04

PAH 4.00E-05 2.33E-02 5.82E-03 85% 3.49E-03 8.73E-04

Totals Total annual HAP based on either 8760 hrs on natural gas or 500 hrs on ULSD and

8260 hrs on natural gas

Total hourly HAP based on the max for either NG or ULSD fuels

Exemption Levels Exempt?

Ib/hr ton/yr Ib/hr tpy Ib/hr tpy

1,3-Butadiene 2.79E-03 2.08E-03 1.452 3.19 Yes Yes

Acetaldehyde 7.11E-03 3.11E-02 8.91 26.1 Yes Yes

Acrolein 1.14E-03 4.98E-03 0.02277 0.03335 Yes Yes

Benzene 9.61E-03 1.12E-02 2.112 4.64 Yes Yes

Ethyl Benzene 5.69E-03 2.49E-02 17.919 62.93 Yes Yes

Formaldehyde 1.26E-01 5.53E-01 0.0825 0.174 No No

Naphthalene 6.11E-03 2.48E-03 2.607 7.54 Yes Yes

PAHa 6.99E-03 3.36E-03 0.0132 0.029 Yes Yes

Propylene Oxide 5.16E-03 2.26E-02 3.168 6.96 Yes Yes

Toluene 2.31E-02 1.01E-01 18.645 54.665 Yes Yes

Xylenes 1.14E-02 4.98E-02 21.483 62.93 Yes Yes

Gateway Smart Water Project

Prince George County 52375-02

AMS

Fire Water Pump 250 hp 200 hrs/yr operation

0.45359 kg/lb 138 MMBtu/kgal

7000 Btu/hp-hr 1.754 MMBtu/hr LHV

138 MMBtu/kgal 1.8649 MMBtu/hr HHV

Emissions

Pollutant EF unit Ib/hr tons/yr

1,3-butadiene 3.91E-05 Ib/MMBtu 7.29E -05 7.29E -06

acenaphthene 1.42E-06 Ib/MMBtu 2.65E -06 2.65E -07

acenaphthylene 5.06E-06 Ib/MMBtu 9.44E -06 9.44E -07

acetaldehyde 7.67E-04 Ib/MMBtu 1.43E -03 1.43E -04

acrolein 9.25E-05 Ib/MMBtu 1.7.3E -04 1.73E -05

anthracene 1.87E-06 Ib/MMBtu 3.49E -06 3.49E -07

benzene 9.33E-04 Ib/MMBtu 1.74E -03 1.74E -04

benzoanthracene 1.68E-06 Ib/MMBtu 3.13E -06 3.13E -07

benzopyrene 1.88E-07 Ib/MMBtu 3.51E -07 3.51E -08

benzo(b)fluoranthene 9.91E-08 Ib/MMBtu 1.85E -07 1.85E -08

benzoperylene 4.89E-07 Ib/MMBtu 9.12E -07 9.12E -08

benzo(k)fluoranthene 1.55E-07 Ib/MMBtu 2.89E -07 2.89E -08

chrysene 3.53E-07 Ib/MMBtu 6.58E -07 6.58E -08

dibenzo anthracene 5.83E-07 Ib/MMBtu 1.09E -06 1.09E -07

fluoranthene 7.61E-06 Ib/MMBtu 1.42E -05 1.42E -06

fluorene 2.92E-05 Ib/MMBtu 5.45E -05 5.45E -06

formaldehyde 1.18E-03 Ib/MMBtu 2.20E -03 2.20E -04

indeno pyrene 3.75E-07 Ib/MMBtu 6.99E -07 6.99E -08

naphthalene 8.48E-05 Ib/MMBtu 1.58E -04 1.58E -05

phenanthrene 2.94E-05 Ib/MMBtu 5.48E -05 5.48E -06

propylene 2.58E-03 Ib/MMBtu 4.81E -03 4.81E--04

pyrene 4.78E-06 Ib/MMBtu 8.91E -06 8.91E--07

toluene 4.09E-04 Ib/MMBtu 7.63E -04 7.63E--05

xylene 2.85E-04 Ib/MMBtu 5.31E--04 5.31E-05

Gateway Smart Water Project Prince George County 52375-02 AMS

Four Electical Circuit Breakers 60 lb ofSF6/breaker

4 breakers

1.0% leakage rate

2.4 Ib/yr leakage

0.0012 tpySF6

28.68 tpy C02-e (@ 23,900 GWP)

Leakage will be monitored by

gas density gauges on the breakers

Public Notice - Environmental Permit

PURPOSE OF NOTICE: To seek public comment and announce a public hearing and an information briefing on a draft permit from the Department of Environmental Quality to limit air pollution from a facility in Prince George County, Virginia. PUBLIC COMMENT PERIOD: July 9, 2012 to August 23, 2012 INFORMATION BRIEFING AND PUBLIC HEARING: Prince George County Administration Building Meeting Room, 6602 Courts Drive in Prince George, Virginia on August 8, 2012 from 5:30 to 6pm (information briefing) and then from 6-7 pm (public hearing for comments). PERMIT NAME: Prevention of Significant Deterioration Permit issued by DEQ, under the authority of the Air Pollution Control Board APPLICANT NAME AND REGISTRATION NUMBER: Gateway Cogeneration 1, LLC; #52375 FACILITY NAME AND ADDRESS: Smart Water Project, Chudoba Parkway, Prince George, VA 23875 PROJECT DESCRIPTION: Gateway Cogeneration 1, LLC has applied for a permit to build the Smart Water Project. The facility will be classified as a major source of air pollution and will be located on Chudoba Parkway, east of 295, one mile from the interchange with Rte. 460. The maximum annual emissions of air pollutants from the facility are expected to be: 592,000 tons of carbon dioxide equivalents, 48.8 tons of particulate matter, 49.8 tons of carbon monoxide, 39.0 tons of nitrogen oxides, 23.4 tons of volatile organic compounds, 7.8 tons of sulfur dioxide, and 0.6 tons of formaldehyde. The applicant proposes to use 10,100 million cubic feet of natural gas and 4.2 million gallons of ultra low sulfur diesel. Modeling has shown that the proposed project does not cause or significantly contribute to a predicted violation of any applicable NAAQS, Class I or Class II PSD increment. Air emissions from the facility and associated construction and industrial growth are not anticipated to adversely impact visibility, soils, or vegetation. HOW TO COMMENT AND/OR REQUEST BOARD CONSIDERATION: DEQ accepts comments and requests for Board consideration by e-mail, fax or postal mail. All comments and requests must be in writing and be received by DEQ during the comment period. Submittals must include the names, mailing addresses and telephone numbers of the commenter/requester and of all persons represented by the commenter/requester. A request for Board consideration must also include: 1) The reason why Board consideration is requested. 2) A brief, informal statement regarding the nature and extent of the interest of the requester or of those represented by the requestor, including how and to what extent such interest would be directly and adversely affected by the permit. 3) Specific references, where possible, to terms and conditions of the permit with suggested revisions. Board consideration may be granted if public response is significant, based on individual requests for Board consideration, and there are substantial, disputed issues relevant to the permit. Contact for public comments, document -aquests and additional information: Alison Sinclair, DEQ -Piedmont Office, 4949-A Cox Rd., Glen Allen, VA 23060; Phone: (804) 527-5155; E-mail: alison.sinclair@deq.virginia.gov; Fax: (804) 527-5106. The public may review the draft permit and application at the DEQ office named above, on the DEQ website (www.deq.virqinia.gov), or may request copies of the documents from the contact person listed above.

COMMONWEALTH of VIRGINIA DEPARTMENT OF ENVIRONMENTAL QUALITY

PIEDMONT REGIONAL OFFICE Douglas W. Domenech 4949A Cox Road, Glen Allen, Virginia 23060

Secretary of Natural Resources (804) 527-5020 Fax (804) 527-5106 www.deq.virginia.gov

July 10,2012

Mr. Henry D. Parker, Jr. Chairman - Prince George County Board of Supervisors 14001 James River Dr. Hopewell, VA 23860

Dear Mr. Parker:

Attached, please find a Public Notice seeking public comment on a draft air pollution permit for Gateway Green Energy's Smart Water project to be located in Prince George County, Virginia. A copy of the draft permit can be found at http://www.deq.virginia.gov/Programs/Air/PublicNotices/AirPermits.aspx . Please contact me if you would like additional information.

Sincerely,

Alison M. Sinclair Environmental Specialist II, Sr.

David K. Paylor Director

Michael P. Murphy Regional Director

Sinclair, Alison (DEQ)

From: Sinclair, Alison (DEQ) Sent: Monday, July 09, 2012 2:28 PM To: 'DelRDance@house.virginia.gov'; 'DelRlngram@house.virginia.gov';

'DelRMorris@house.virginia.gov'; 'DelRTyler@house.virginia.gov'; 'districtl 3 ©senate.virginia.gov'; 'martindistrict@comcast.net'; 'district16@senate.virginia.gov'; 'rbailey@trinityconsultants.com'; 'tballo@earthjustice.org'; 'mbandyk@snl.com'; 'mebarker@cox.net'; 'barrarh@chesterfield.gov'; 'cbednar@smurfit.com'; 'Robert_M_Bisha@dom.com'; 'mek67@law.georgetown.edu'; 'jchristman@hunton.com'; 'john@johnclinelaw.com'; 'pamela_faggert@dom.com'; 'bfults@esswetlands.com'; 'john.fuoto@amec.com'; 'andy_gates@dom.com'; 'ragesser@gapac.com'; 'jgrandstaff@hrwtf.org'; 'rgreene@ingenco.com'; 'thansell@appalshop.org'; 'drewh@dominioncarolina.com'; 'dkaiser@stratusenvironmental.com'; 'dkleis@monsol.com'; 'cjaffe@selcva.org'; 'tknauer@Tkenvirolaw.com'; 'philip_knause@dom.com'; 'dskoger@kogerair.com'; 'bkoski@compassenergy.net'; 'chad@bartlettcontrols.com'; 'smullins@industrialinfo.com'; 'smullins@industrialinfo.com'; 'oldag84@yahoo.com'; 'jpnovotny@aep.com'; 'jpeterson@environmentalintegrity.org'; 'mlphilli@kaufcan.com'; 'lpowell@chemtradelogistics.com'; 'gprelewicz@fairfaxwater.org'; 'loriroth58@gmail.com'; 'claudlaw@aol.com'; 'nsaji@fairfaxwater.org'; 'mark.singer@ramca.info'; 'walterrep@msn.com'; 'dmorris@craterpdc.org'; 'administration@princegeorgeva.org'; 'Robert.Middaugh@jamescitycountyva.gov'; 'countyadministrator@chesterfield.gov'; 'wjohnson@petersburg-va.org'; 'jccboard@jamescitycountyva.gov'; 'geckerd@chesterfield.gov'; 'citycouncil@petersburg-va.org'

Subject: Notice of Public Comment Attachments: 52375_002_12_PN.pdf

Attached, please find a Public Notice seeking public comment on a draft air pollution permit for Gateway Green Energy's Smart Water project to be located in Prince George County, Virginia. A copy of the draft permit can be found at http://www.deq.virginia.gov/Programs/Air/PublicNotices/AirPermits.aspx

Alison Sinclair Environmental Specialist II DEQ Piedmont Regional Office 4949-A Cox Road Glen Allen, VA 23060 Ph. (804) 527-5155 Fax. (804) 527-5106

l

The Progress Index (Under act P.L. 877 No 160. July 9,1976) Commonwealth of Virginia, City of Petersburg

OF DEQ PIEDMONT RE PO BOX 1105 4949 A COX ROAD RICHMOND VA 23220

Account # 152747 Order # 80961350 Ad Price: 359.56

Vickie Jacobs Being duly sworn according to law deposes and says that she is Billing clerk for The Progress Index, owner and publisher of The Progress Index, a newspaper of general circulation, established in 1865, published in the city of Petersburg , county and state aforesaid, and that the printed notice or publication hereto attached is exactly as printed in the regular editions of the said newspaper on the following dates:

07/08/2012

Affiant further deposes and says that neither the affiant nor The Progress Index is interested in the subject matter of the aforesaid notice or advertisement and that all allegations in the forpgejrjg stalerrteiit as time, place and character or publication are true

Sworn and subscribed tojjefore me this 11th day of Ju)y^A.U. , 2012

(Notary Public) Carmen C. Hardy

| I _ J _ I _ _ ^ § § ^ ^ Sunday, Julyj3_2012

Public Notice Environmental Permit

I PURPOSE OF NOTICE: To seek public comment and an­nounce a public hearing and an information briefing on a

[ draft permit from the Depart­ment of Environmental Quali­ty to limit air pollution from a facility in Prince George County, Virginia.

PUBLIC COMMENT PERIOD: July 9, 2012 to August 23, 2012

INFORMATION BRIEFING AND PUBLIC HEARING: Prince George County Admin­istration Building Meeting Room, 6602 Courts Drive in Prince George, Virginia on August 8, 2012 from 5:30 to 6pm (information briefing) and then from 6-7 pm (public hearing for comments).

PERMIT NAME: Prevention of Significant Deterioration Per­mit issued by DEQ, under the authority of the Air Pollution Control Board

APPLICANT NAME AND REG­ISTRATION NUMBER: Gate­way Cogeneration 1, LLC; #52375

FACILITY NAME AND AD­DRESS: Smart Water Project, Chudoba Parkway, Prince George, VA 23875

PROJECT DESCRIPTION Gateway Cogeneration 1, LLC has applied for a permit to build the Smart Water Project. The facility will be Iclassified as a major source of air pollution and will be lo­cated on Chudoba Parkway, east of 295, one mile from the interchange with Rte. 460. The maximum annual emis­sions of air pollutants from the facility are expected to be: 592,000 tons of carbon diox­ide equivalents, 48.8 tons of particulate matter, 49.8 tons of carbon monoxide, 39.0 tons of nitrogen oxides, 23.4 tons of volatile organic com­pounds, 7.8 tons of sulfur dioxide, and 0.6 tons of formaldehyde. The applicant proposes to use 10,100 mil­lion cubic feet of natural gas and 4.2 million gallons of ul­tra low sulfur diesel. Model ing has shown that the pro posed project does not cause or significantly contribute to a, predicted violation of any ap­plicable NAAQS, Class I or Class II PSD increment. Air emissions from the facility and associated construction

, and industrial growth are not 1 anticipated to adversely im-i pact visibility, soils, or vege-lltation.

ilHOW TO COMMENT AND/OR REQUEST BOARD CONSID-

i ERATION: DEQ accepts com-1 . ments and requests for Board [consideration by e-mail, fax or postal mail. All comments and requests must be in writ­ing and be received by DEQ during the comment period. Submittals must include the names, mailing addresses and telephone numbers of the commenter/requester and of all persons represented by the commenter/requester. P request for Board considera tion must also include: 1) The reason why Board considera tion is requested. 2) A brief, informal statement regarding the nature and extent of the interest of the requester or of those represented by the re­questor, including how and to what extent such interest would be directly and ad verse ly affected by the per mit. 3) Specific references where possible, to terms and conditions of the permit with suggested revisions. Board consideration may be granted if public response is signifi cant, based on individual re quests for Board considera tion, and there are substan tial, disputed issues relevant to the permit.

Contact for public comments, document requests and addi tional information: Alison Sin clair, DEQ Piedmont Office, 4949-A Cox Rd., Glen Allen, VA 23060; Phone: (804) 527-5155; E-mail: alison.sin-clair@deq.virginia.gov; Fax: (804) 527-5106. The public may review the draft permit and application at the DEQ of­fice named above, on the DEQ website (www.deq.vir-ginia.gov), or may request copies of the documents from the contact person listed ^bove.

Have something to sell? CALL US TODAY

804-490-0044

Information Briefing for Gateway Cogeneration 1 LLC - Smart Water Project in Prince George County Virginia

• Project is to be located on Chudoba Parkway between Purdue and the Crosspoint Business Park, 1 mile east of the interchange of 295 and Rt. 460.

• Consists of two combustion turbines, each with a heat recovery steam generator (total of 160 MW power output), an emergency diesel fire pump, a cooling tower, four electrical circuit breakers and a diesel storage tank.

• Burns primarily natural gas but has the capacity to burn up to 500 hours of ultra low sulfur diesel oil as backup.

• Because the facility is located in an attainment area for all pollutants, and the source is proposing to add a major new source of pollutants (greenhouse gasses), the source must show that they will not contribute to a significant deterioration of air quality in the region.

• The source submitted a Prevention of Significant Deterioration (PSD) permit application to DEQ in January 2012.

• EPA had issued new Greenhouse Gas (GHG) permitting regulations which required any major new source of GHG (including CO2, methane, nitrous oxide, sulfur hexafluoride and HFCs) to receive a PSD permit after July 1, 2011.

• Gateway proposed GHG emissions over 100,000 tons/yr so that triggered PSD permitting for a major new source of pollutants in an attainment area. In addition, the proposed emissions of Particulate Matter (including PMio and PM2.5) was over the PSD significance level (15 tons/yr and 10 tons, respectively) and so PSD permitting applied to PM as well.

• Proposed emissions:

PM10 48.8 tons/yr

PM2.5 48.8 tons/yr

S02 7.8 tons/yr

NOx 39.0 tons/yr

CO 49.8 tons/yr

VOC 23.4 tons/yr

C02-e 591,981.0 tons/yr

Formaldehyde 1100.0 lbs/yr

• Because GHG, PMio and PM2.5 were subject to PSD permitting, they were also subject to applying Best Available Control Technology (BACT). Other pollutants triggered minor New Source Review permitting and were also subject to State BACT. Following is a summary of BACT for the source:

Pollutant Primary BACT Control Secondary BACT (State)

Compliance

NO„ (State) Turbines 2.0 ppmvd - gas (3-hour avg.) 5.0 ppmvd - ULSD (3-hour avg.)

Water injection and SCR 19.5 tons/yr NOx CEMS

Pollutant Primary BACT Control Secondary BACT (State)

Compliance

CO (State) Turbines 4.0 ppmvd (3-hour avg.)

Oxidation catalyst 24.9 tons/yr CO CEMS

PM 1 0 (Federal and State)/PM2 5

(Federal)

Turbines 5.0 lbs/hr gas (3-hour avg.) 15.0 lbs/hr ULSD (3-hour avg.)

Proper operation and maintenance on the turbines

stack test

PM 1 0 (Federal and State)/PM2 5

(Federal)

Fire Pump 0.15 g/hp-hr

Clean fuel and good combustion practices

stack test

PM 1 0 (Federal and State)/PM2 5

(Federal) Cooling Tower Drift rate of 0.001% of circulating water flow

Low total dissolved solids (TDS) and drift eliminators

Weekly water quality testing for TDS

VOC (State) Turbines 2.0 ppmvd (3-hour avg.)

Oxidation catalyst 11.7 tons/yr stack test and CO CEMS compliance

C0 2-e (Federal)

Turbines 8,983 Btu/kWh (HHV gross) and 1050 Ib/MWh

Energy efficient combustion practices and low GHG fuels

ASME Performance Test Code on Overall Plant Performance (PTC 46) and C0 2 CEMS (Part 75)

C0 2-e (Federal) Fire Pump 74.21 kg/MMBtu

Fuel-efficient design 74.21 kg/MMBtu HHV and fuel usage monitoring

C0 2-e (Federal)

Electrical Circuit breakers Enclosed-pressure type breaker and leak detection

Audible alarm with decreased pressure.

• The source also modeled pollutants (PMio, PM2.5, and formaldehyde) to make sure they would be in compliance with the National Ambient Air Quality Standards (NAAQS) and PSD increment, and, in the case of formaldehyde, the Significant Ambient Air Concentrations (SAAC). DEQ reviewed this modeling carefully and found no violation of any standards or PSD increment.

• The source will have to test for PMio emissions from the turbines and will have to conduct an Overall Plant Performance Test for the heat rate limit of the combustion turbine.

• The source will have to operate and maintain Continuous Emissions Monitors (CEMS) for NOx, C02 and CO.

• The source will have to conduct Visible Emission Evaluations for opacity from the turbines while burning oil to make sure they aren't contributing to visibility problems.

• The source will have to keep records of annual fuel consumption (monthly basis), hours of operation of the fire pump, start up and shutdown emissions, CEMS performance data, weekly total dissolved solids content of the cooling water and records of unscheduled maintenance and operator training.

• The source must submit to annual inspections by DEQ inspectors and emission reporting.